Currently, in situ technologies are used to extract heavy oil or bitumen from oil sands deposits at depths greater than about 70 meters. Surface mining these deposits is not economical. Depending on the particular process used and the operating conditions, in situ processes can produce between approximately 10% and 60% of the original volume of oil in place. The produced oil typically consists of solution gas and low API (American Petroleum Institute) gravity oil, having a viscosity greater than approximately 1000 cP (centipoise) at surface conditions. Heavy oil or bitumen is produced to the surface and is often diluted with a solvent (e.g., a diluent or gas condensate) to facilitate piping the product to a surface facility, such as a heavy oil upgrader for upgrading and conversion into a synthetic crude oil. Synthetic crude oil is a value-added product that can be used in conventional crude refineries for conversion to gasoline, kerosene and other petrochemical products.
Conventional upgrading occurs in a refinery at surface and can use processes such as visbreaking, thermal cracking, or catalytic processes such as hydrocracking and hydrotreating to reduce the average molecular weight of an oil, increase the hydrogen content, reduce the sulphur and nitrogen contents and tailor the composition of the oil to a desired product stream. Similar approaches have been suggested for upgrading in a reservoir whereby catalysts and a recovery process are combined to effect these beneficial changes in the reservoir itself. Examples include the THAI process, an acronym for “toe-to-heel air injection”, and the CAPRI process, a version of THAI that uses catalyst.
Conventional techniques to recover heavy oil or bitumen are generally either thermal or non-thermal processes. Cyclic Steam Stimulation (CSS) is an example of a thermal recovery process. In a first stage of the process, a volume of high pressure steam is injected through an injection well into an oil sands formation to heat the bitumen. The steam is generally injected at pressures above the fracture pressure of the reservoir, so a steam fracture is formed in the reservoir during injection. In a second optional stage, the reservoir is allowed to “soak”, during which the steam condenses and releases its latent heat to the formation thus further heating the oil sands. In a third stage, the injection well is switched to a production well and reservoir fluids including steam, condensed steam, mobile bitumen, and gas are produced to the surface. The production stage continues while economic rates of bitumen recovery are achieved. After the bitumen rate becomes too small for the process to be economic, the well is switched to injection and the first stage starts again. The stages are repeated for as many cycles as the process is economic. The CSS method relies on formation recompaction, solution gas drive, and gravity drainage as the major drive mechanisms for heavy oil and bitumen recovery. The major costs associated with CSS are steam generation, water handling and treatment, and recycling.
Another example of a thermal recovery process is Steam Assisted Gravity Drainage (SAGD). Typically, two horizontal wells are drilled substantially parallel to each other in a heavy oil or bitumen reservoir, with one well positioned vertically above the second well. The upper well is the injection well and the lower well is the production well. Steam is injected through the upper well and forms a vapor phase chamber that grows within the reservoir. The injected steam reaches the edges of the depletion steam chamber and delivers latent heat to the surrounding oil sand. The oil within the oil sand is heated and consequently its viscosity decreases. The oil drains under the action of gravity within and along the edges of the steam chamber toward the production well. The reservoir fluids, i.e., the heated oil and condensate, enter the production well and are motivated, either by natural pressure or by a pump, to the surface. In the initial stages of the process, the steam chamber grows vertically. After the chamber reaches the top of the reservoir, it may grow laterally, however, heat from the steam can be lost to shale and other material found at the upper boundary of the oil-rich zone in the reservoir. Generally, the major capital and operating costs of SAGD are tied to the steam generation and water handling, treatment, and recycling facilities.
A variant of SAGD is the Steam and Gas Push (SAGP) process. In SAGP, steam and a non-condensable gas are co-injected into the reservoir, and the non-condensable gas forms an insulating layer at the top of the steam chamber. This can lower heat losses to the cap rock and improve the thermal efficiency of the recovery process. The well configuration is the same as the standard SAGD configuration. There are other examples of processes that use steam with different well configurations to recover heavy oil and bitumen.
A non-thermal process is referred to as Cold Production (CP). In CP techniques, the live oil viscosity (i.e., the viscosity of oil with associated solution gas) is typically low enough and the driving pressure gradient due to solution-gas drive, large enough that the oil together with gas bubbles and possibly reservoir matrix material (e.g., sand or silt) can be produced to the surface. The oil is often produced as a foamy oil phase with gas bubbles evolving from the viscous oil matrix.
Vapor Extraction (VAPEX) is another non-thermal recovery technique that involves injecting vaporized solvents into heavy oil deposits. The injected solvent enters a vapor chamber and flows to the chamber edges. At the edges, the solvent condenses and mixes with the oil, diluting it and lowering its viscosity so that it can flow under the action of gravity drainage to a production well. Similar to SAGD, the production well is positioned below the injection well and the vapor-chamber that is created above the injection well.